Investor Presentation

Transcription

1 1 Investor Presentation February 2017

2 Forward-Looking Statements and Other Disclaimers 2 FORWARD-LOOKING STATEMENTS This presentation and the oral statements made in connection therewith may contain forward looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical fact, regarding Rice Energy s strategy, future operations, financial position, estimated revenues and income/losses, projected costs, as amended, prospects, plans and objectives of management are forward-looking statements. These statements often include the words could, believe, anticipate, may, assume, forecast, position, predict, strategy, expect, intend, plan, estimate, project, budget, potential, guidance, or continue and similar expressions intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. Without limiting the generality of the foregoing, forward-looking statements contained in this presentation specifically include estimates of Rice Energy s reserves, expectations of plans, strategies, objectives and anticipated financial and operating results of Rice Energy, including as to Rice Energy s drilling program, production, hedging activities, capital expenditure levels and other guidance included in this presentation. These forward-looking statements are based on Rice Energy s current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events. Rice Energy assumes no obligation to and does not intend to update any forward looking statements included herein. You are cautioned not to place undue reliance on any forward-looking statements. Rice Energy cautions you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond their control, incident to the exploration for and development, production, gathering and sale of natural gas, natural gas liquids and oil. These risks include, but are not limited to, commodity price volatility; inflation; lack of availability of drilling and production equipment and services; environmental risks; drilling and other operating risks; regulatory changes; the uncertainty inherent in estimating natural gas reserves and in projecting future rates of production, cash flow and access to capital; the timing of development expenditures; risks relating to joint venture operations; and the other risks described under Risk Factors in Rice Energy s most recent Form 10-K, Form 10-Q and other filings with the Securities and Exchange Commission. Should one or more of these risks or uncertainties occur, or should underlying assumptions prove incorrect, Rice Energy s actual results and plans could differ materially from those expressed in any forward-looking statements. This presentation has been prepared by Rice Energy and includes market data and other statistical information from sources believed by Rice Energy to be reliable, including independent industry publications, government publications or other published independent sources. Some data are also based on Rice Energy s good faith estimates, which are derived from its review of internal sources as well as the independent sources described above. Although Rice Energy believes these sources are reliable, it has not independently verified the information and cannot guarantee its accuracy and completeness. NON-PROVEN OIL AND GAS RESERVES The SEC permits oil and gas companies, in their filings with the SEC, to disclose proved reserves, which are reserve estimates that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions and certain probable and possible reserves that meet the SEC s definition for such terms. We may use certain broader terms such as EUR (estimated ultimate recovery of resources), and we may use other descriptions of volumes of potentially recoverable hydrocarbon resources throughout this presentation that the SEC does not permit to be included in SEC filings. These broader classifications do not constitute reserves as defined by the SEC, and we do not attempt to distinguish these classifications from probable or possible reserves as defined by SEC guidelines. Our estimates of EURs have been prepared by our independent reserve engineers. These estimates are by their nature more speculative than estimates of proved, probable and possible reserves and accordingly are subject to substantially greater risk of being actually realized, particularly in areas or zones where there has been limited or no drilling history. We include these estimates to demonstrate what we believe to be the potential for future drilling and production by the company. Actual locations drilled and quantities that may be ultimately recovered from our properties will differ substantially. In addition, we have made no commitment to drill all of the drilling locations which have been attributed to these quantities. Ultimate recoveries will be dependent upon numerous factors including actual encountered geological conditions, the impact of future oil and gas pricing, exploration and development costs, and our future drilling decisions and budgets based upon our future evaluation of risk, returns and the availability of capital and, in many areas, the outcome of negotiation of drilling arrangements with holders of adjacent or fractional interest leases. Estimates of resource potential and other figures may change significantly as development of our properties provide additional data and therefore actual quantities that may ultimately be recovered will likely differ from these estimates. Our forecast and expectations for future periods are dependent upon many assumptions, including estimates of production decline rates from existing wells, the undertaking and outcome of future drilling activity and activity that may be affected by significant commodity price declines or drilling cost increases. Certain of Rice Energy's wells are named after superheroes and monster trucks, some of which may be trademarked. Despite their size and strength, Rice Energy's wells are in no manner affiliated with such superheroes or monster trucks. Initial production rates are subject to decline over time and should not be regarded as reflective of sustained production levels. In particular, production from horizontal drilling in shale oil and natural gas resource plays and tight natural gas plays that are stimulated with extensive pressure fracturing are typically characterized by significant early declines in production rates.

3 Non-GAAP Financial Measures 3 Rice Energy Adjusted EBITDAX and Further Adjusted EBITDAX Adjusted EBITDAX and Further Adjusted EBITDAX are supplemental non-gaap financial measures that are used by management and external users of RICE s consolidated financial statements, such as industry analysts, investors, lenders and rating agencies. RICE defines Adjusted EBITDAX as net income (loss) before non-controlling interest; interest expense; income taxes; depreciation, depletion and amortization; amortization of deferred financing costs; amortization of intangible assets; derivative fair value (gain) loss, excluding net cash receipts on settled derivative instruments; non-cash stock compensation expense; non-cash incentive unit expense; exploration expenses; and other non-recurring items. RICE defines Further Adjusted EBIDAX as Adjusted EBIDAX after non-controlling interest and water revenue adjustment. Neither Adjusted EBITDAX nor Further Adjusted EBITDAX is a measure of net income as determined by United States generally accepted accounting principles, or GAAP. Management believes Adjusted EBITDAX is useful because it allows them to more effectively evaluate RICE s operating performance and compare the results of RICE s operations from period to period and against its peers without regard to its financing methods or capital structure. RICE excludes the items listed above from net income (loss) in arriving at Adjusted EBITDAX because these amounts can vary substantially from company to company within the industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Management believes Further Adjusted EBITDAX is useful because it allows them to assess the level of consolidated leverage of the company and compare this level to peers. The adjustments made to Adjusted EBITDAX to calculate Further Adjusted EBITDAX address the intercompany eliminations of items impacting Adjusted EBITDAX as a result of the consolidation of RMP, the outstanding indebtedness of which is consolidated with that of the company without regard to non-controlling interest. These adjustments include the addition of non-controlling interest as well as a water revenue adjustment attributable to charges for fresh water delivery services and produced water hauling services provided by RMP to the company, a charge that generates revenue for RMP but does not have a corresponding expense at the company level, as such costs are capitalized. Adjusted EBITDAX and Further Adjusted EBITDAX should not be considered as alternatives to, or more meaningful than, net income as determined in accordance with GAAP or as indicators of RICE s operating performance or liquidity. Certain items excluded from Adjusted EBITDAX and Further Adjusted EBITDAX are significant components in understanding and assessing a company s financial performance, such as a company s cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of Adjusted EBITDAX or Further Adjusted EBITDAX. RICE s computations of Adjusted EBITDAX and Further Adjusted EBITDAX may not be comparable to other similarly titled measures of other companies. RICE believes that these measures are a widely followed measures of operating performance used by investors. RMH Adjusted EBITDA is a supplemental non-gaap financial measure that is used by management and external users of the RMH s financial statements, such as industry analysts, investors, lenders and rating agencies. RMH defines Adjusted EBITDA as operating income (loss) before incentive unit expense; acquisition expense; impairment of fixed assets; stock compensation expense; depreciation, depletion and amortization; and other non-recurring items. Adjusted EBITDA is not a measure of operating income as determined by United States generally accepted accounting principles, or GAAP. Management believes RMH Adjusted EBITDA is useful because it allows them to more effectively evaluate RMH s operating performance and compare the results of RMH s operations from period to period without regard to its financing methods or capital structure. RMH excludes the items listed above from operating income (loss) in arriving at Adjusted EBITDA because these amounts can vary substantially from company to company within the industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. RMH Adjusted EBITDA should not be considered as an alternative to, or more meaningful than, operating income as determined in accordance with GAAP or as indicators of RMH s operating performance or liquidity. Certain items excluded from Adjusted EBITDA are significant components in understanding and assessing a company s financial performance, such as a company s cost of capital, as well as the historic costs of depreciable assets, none of which are components of Adjusted EBITDA. RMH s computations of Adjusted EBITDA may not be comparable to other similarly titled measures of other companies. RICE believes that the measure is a widely followed measures of operating performance used by investors. Management has not provided projected RMH net income or a reconciliation of projected RMH Adjusted EBITDA to projected RMH net income, the most comparable financial measure calculated in accordance with GAAP. Management is unable to project RMH net income because this metric includes the impact of certain non-cash items such as depreciation expense that management is unable to project with any reasonable degree of accuracy without unreasonable effort. Therefore, management is unable to provide projected RMH net income, or the related reconciliation of projected RMH Adjusted EBITDA to projected net income. RMP Adjusted EBITDA, Distributable Cash Flow and DCF Coverage Ratio Adjusted EBITDA is a supplemental non-gaap financial measure that is used by management and external users of RMP s consolidated financial statements, such as securities analysts, investors and lenders. Management defines Adjusted EBITDA as net income (loss) before interest expense, depreciation expense, amortization expense, non-cash stock compensation expense, amortization of deferred financing costs and other non-recurring items. Adjusted EBITDA is not a measure of net income as determined by GAAP. Distributable cash flow and DCF coverage ratio are supplemental non-gaap financial measures that are used by management and external users of RMP s consolidated financial statements, such as securities analysts, investors and lenders. Management defines distributable cash flow as Adjusted EBITDA less cash interest expense, and estimated maintenance capital expenditures. Management defines DCF coverage ratio as distributable cash flow divided by total distributions declared. Distributable cash flow does not reflect changes in working capital balances and is not a presentation made in accordance with GAAP. Adjusted EBITDA, distributable cash flow and DCF coverage ratio are non-gaap supplemental financial measures that management and external users of RMP s consolidated financial statements, such as industry analysts, investors, lenders and rating agencies, may use to assess the financial performance of RMP s assets, without regard to financing methods, capital structure or historical cost basis; RMP s operating performance and return on capital as compared to other companies in the midstream energy sector, without regard to historical cost basis or, in the case of Adjusted EBITDA, financing or capital structure; RMP s ability to incur and service debt and fund capital expenditures; the ability of RMP s assets to generate sufficient cash flow to make distributions to RMP s unitholders; and the viability of acquisitions and other capital expenditure projects and the returns on investment of various investment opportunities. Management believes that the presentation of Adjusted EBITDA, distributable cash flow and DCF coverage ratio will provide useful information to investors in assessing RMP s financial condition and results of operations. The GAAP measures most directly comparable to Adjusted EBITDA and distributable cash flow are net income and net cash provided by (used in) operating activities. RMP s non-gaap financial measures of Adjusted EBITDA and distributable cash flow should not be considered as an alternative to GAAP net income or net cash provided by operating activities. Each of Adjusted EBITDA and distributable cash flow has important limitations as an analytical tool because it excludes some but not all items that affect net income and net cash provided by operating activities. You should not consider Adjusted EBITDA, distributable cash flow or DCF coverage ratio in isolation or as a substitute for analysis of RMP s results as reported under GAAP. Because Adjusted EBITDA and distributable cash flow and DCF coverage ratio may be defined differently by other companies in the industry, RMP s definitions of Adjusted EBITDA, distributable cash flow and DCF coverage ratio may not be comparable to similarly titled measures of other companies, thereby diminishing its utility. Management has not provided projected net income or net cash provided by operating activities or reconciliations of its projected Adjusted EBITDA and projected distributable cash flow to projected net income and projected net cash provided by operating activities, respectively, the most comparable financial measures calculated in accordance with GAAP. Management is unable to project net cash provided by operating activities because this metric includes the impact of changes in operating assets and liabilities related to the timing of cash receipts and disbursements that may not relate to the period in which the operating activities occurred. Management is unable to project these timing differences with any reasonable degree of accuracy to a specific day, three or more months in advance. Therefore, management is unable to provide projected net cash provided by operating activities, or the related reconciliation of projected distributable cash flow to projected net cash provided by operating activities. In addition, management is unable to project net income because this metric includes the impact of certain non-cash items such as depreciation expense that management is unable to project with any reasonable degree of accuracy without unreasonable effort. Therefore, management is unable to provide projected net income, or the related reconciliation of projected Adjusted EBITDA to projected net income. Further, management does not provide guidance with respect to the intra-year timing of its capital spending, which impact debt and equity and equity earnings, among other items, that are reconciling items between Adjusted EBITDA and net income. The timing of capital expenditures is volatile as it depends on weather, regulatory approvals, contractor availability, system performance and various other items. Management provides a range for the forecasts of Adjusted EBITDA and distributable cash flow to allow for the variability in the timing of spending and the impact on the related reconciling items, many of which interplay with each other. Therefore, the reconciliation of Adjusted EBITDA to projected net income is not available without unreasonable effort.

4 RICE Adjusted EBITDAX Reconciliation Twelve Months Ended Twelve Months Ended Twelve Months Ended Three Months Ended ($ in thousands) December 31, 2014 December 31, 2015 December 31, 2016 December 31, 2016 Adjusted EBITDAX reconciliation to net income (loss): Net income $219,035 ($267,999) ($248,820) ($196,605) Interest expense 50,191 87,446 99,627 25,883 Depreciation, depletion and amortization 156, , , ,323 Impairment of fixed assets 23,057 20,462 Impairment of goodwill 294,908 Impairment of gas properties 18,250 20,853 20,853 Amortization of deferred financing costs 2,495 5,124 7,545 3,129 Amoritization of intangible assets 1,156 1,632 1, (Gain) Loss on derivative instruments (1) (186,477) (273,748) 220, ,775 Net cash receipts on settled derivative instruments (1) (18,784) 193, ,071 34,720 Acquisition expense 2,339 1,235 6,109 4,938 Non-cash stock compensation expense 16,528 21,915 4,921 Non-cash incentive unit expense 36,097 51,761 6,859 Income tax expense (benefit) 91,600 12,118 (142,212) (104,372) Gain from sale of interest in gas properties (953) Gain on purchase of Marcellus joint venture (203,579) Exploration expense 4,225 3,137 15,159 5,225 Loss on extinguishment of debt 7,654 Acquisition break-up fee (1,939) Other expense 121,066 4,380 6,511 1,384 Non-controlling interest attributable to midstream entities (581) (23,337) (75,415) (19,880) Adjusted EBITDAX (2) $246,610 $431,510 $575,547 $202,027 Note: See slide 3 for important disclosures regarding non-gaap financial measures. 1. The adjustments for the derivative fair value (gains) losses and net cash receipts on settled commodity derivative instruments have the effect of adjusting net income (loss) for changes in the fair value of derivative instruments, which are recognized at the end of each accounting period because we do not designate commodity derivative instruments as accounting hedges. This results in reflecting commodity derivative gains and losses within Adjusted EBITDAX on a cash basis during the period the derivatives settled. 2. The above Adjusted EBITDAX reconciliation deducts the impact of non-controlling interest attributable to midstream entities and excludes the elimination of intercompany water revenues between Rice Energy subsidiaries and Rice Midstream Partners of $19.9 million and $17.2 million for the three months ended December 31, 2016, respectively, and $75.4 million and $55.9 million for the year ended December 31, 2016, respectively. When adjusting for these impacts, our Further Adjusted EBITDAX is $239.1 million for the three months ended December 31, 2016, and $706.8 million for the year ended December 31, Our consolidated net debt to LTM Further Adjusted EBITDAX ratio is 1.5x. Also included in the above reconciliation is the non-controlling interest attributable to Rice Energy Operating LLC, as we view our business on a fully diluted basis. 4

5 RMP Adjusted EBITDA and DCF Reconciliation Three Months Ended Twelve Months Ended Twelve Months Ended ($ in thousands) December 31, 2016 December 31, 2016 December 31, 2015 Reconciliation of Net Income to Adjusted EBITDA and DCF: Net income $34,260 $121,610 $52,495 Interest expense 1,562 3,931 3,164 Income tax expense - - 5,812 Depreciation expense 7,456 25,170 16,399 Amortization of intangible assets 412 1,634 1,632 Acquisition costs Non-cash equity compensation expense 145 2,873 4,501 Incentive unit expense - - 1,044 Amortization of deferred financing costs 1,046 1, Other expense 1,292 1, Adjusted EBITDA attributable to Water Assets prior to acquisition (1) - - (22,386) Adjusted EBITDA $46,225 $158,353 $63,780 Cash interest expense (1,562) (3,931) (3,146) Estimated maintenance capital expenditures (2,800) (11,200) (4,480) Distributable cash flow $41,863 $143,222 $56,154 Total distributions declared $26,508 $84,285 $34,038 DCF coverage ratio 1.58x 1.70x 1.22x Reconciliation of Adjusted EBITDA to Cash: Adjusted EBITDA $46,225 $158,353 $63,780 Interest expense (1,562) (3,931) (3,146) Other income (expense) (1,292) (1,531) (543) Acquisition costs (52) (125) - Adjusted EBITDA attributable to Water Assets prior to acquisition (1) ,386 Changes in operating assets and liabilities 1,295 1,350 (12,453) Net cash provided by operating activities $44,614 $154,116 $70,814 Net cash used in investing activities (623,408) (721,087) (379,991) Net cash provided by financing activities 592, , ,748 Net increase in cash 14,201 14,236 (19,237) Cash at the beginning of the period 7,634 7,597 26,834 Cash at the end of the period $21,835 $21,833 $7,597 Note: See slide 3 for important disclosures regarding Non-GAAP financial measures. 1. Adjusted EBITDA attributable to the Water Assets prior to their acquisition is excluded from our adjusted EBITDA calculation as these amounts are not attributable to our limited partners. For the year ended December 31, 2015, the Adjusted EBITDA attributable to the Water Assets prior to acquisition was calculated with net income of $7.3 million plus interest expense of $0.8 million, income tax expense of $5.8 million, depreciation expense of $7.0 million, non-cash equity compensation of $0.4 million and $1.0 million of incentive unit expense. 5

6 RMH Adjusted EBITDA Reconciliation Twelve Months Ended ($ in thousands) December 31, 2016 Reconciliation of Operating Income to Adjusted EBITDA: Operating Income $13,609 Incentive unit expense 2,335 Acquisition expense 484 Impairment of fixed assets 20,292 Stock compensation expense 5,071 Depreciation, depletion and amortization 5,760 Other expense 125 Adjusted EBITDA $47,676 Note: See slide 3 for important disclosures regarding Non-GAAP financial measures. 6

7 7 PV-10 Reconciliation PV-10 is a supplemental non-gaap financial measure and generally differs from standardized measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. PV-10 reflects the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production, future development and abandonment costs, using prices and costs in effect at the determination date, before income taxes, and without giving effect to non-property-related expenses, discounted to a present value using an annual discount rate of 10% in accordance with the guidelines of the SEC. Management and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies without regard to the specific tax characteristics of such entities. Neither PV-10 nor standardized measure represents an estimate of the fair market value of our natural gas properties. The following table presents a reconciliation of the non-gaap financial measure of PV-10 at SEC pricing to the standardized measure of discounted future net cash flows: Twelve Months Ended Twelve Months Ended Twelve Months Ended ($ in millions) December 31, 2016 December 31, 2015 December 31, 2014 Reconciliation to PV-10 Standardized measure of discounted future net cash flows $1,548 $886 $1,308 Discounted future net cash flows for income taxes $ Discounted future net cash flows before income taxes (PV-10) $1,568 $886 $1,744

8 Corporate Strategy 8 Invest in the Core Protect Returns through Firm Transport & Hedging Maintain a Strong, Conservative Balance Sheet Add Value through Midstream Drive Excellence through Innovation and Stewardship Create Long-Term Shareholder Value

9 Rice Energy Overview Ticker Symbol Headquarters Founded IPO date Market cap (1) Enterprise value (1) NYSE: RICE Canonsburg, PA 2007 January 2014 $5.1B $6.6B RICE E&P Rice Midstream Holdings LLC Full-time employees Employee ownership ~475 ~18% 2016 Business Results Net Appalachian acres ~248,000 4Q16 Net production (MMcfe/d) 1,145 Net debt/ebitdax (2) 1.5x GP Holdings (IDRs and LP Interest) OH Gathering and Compression PA Gathering and PA + OH Water Business Note: Share price as of February 15, Share count and balance sheet data as of December 31, Presented as of December 31, 2016 and inclusive of the 40,000,000 Rice Energy Operating LLC common units immediately convertible into 40,000,000 shares of Rice Energy Inc. common stock. 2. Please see "Non-GAAP Financial Measures" for a description of Adjusted EBITDAX and Further Adjusted EBITDAX and related reconciliations to comparable GAAP financial measures. 9

10 Two Streams of Low-Risk, Economic Growth RICE UPSTREAM (E&P) RICE is a technical leader in developing unconventional resource plays Top 20 producer of US natural gas; reached 1 Bcfe/d organic production with fewer wells vs. Appalachia peers ~248,000 core acres in Marcellus and Utica, 100% de-risked, ~80% undeveloped Over 1,100 identified locations with ~95% IRRs at strip pricing (1) 4 horizontal rigs actively developing core Marcellus and Utica 4Q16 production of 1,145 MMcfe/d; ~75% CAGR since IPO RICE MIDSTREAM Production (MMcfe/d) Net Acres (000 s) Throughput (MDth/d) Dedicated Acres (000 s) 1, RICE has built a leading midstream company in the Appalachian basin One of the largest core dry gas dedications: ~377,000 acres from top-tier producers 10 rigs drilling on dedicated acreage 4Q16 throughput of 1,203 MDth/d; ~60% CAGR since IPO Potential midstream value of ~$2.5 - $3.2B (2) Marcellus and Utica economics assume E&P is burdened by 50% of the gathering and compression fee and 50% of water completion fees (Rice s direct subsidiary, REO, owns a 26% LP interest in RMP, 100% of Rice Olympus Midstream and 91.75% of RMP IDRs). Strip pricing as of February 10, 2017 based on weighted average of undeveloped locations; estimated well costs of $875 per lateral foot and $1,235 per lateral foot in the Marcellus and Utica, respectively. Assumes EURs of 15.1 Bcf and 21.0 Bcf in the Marcellus and Utica, respectively. 2. Please see slide titled Significant Unrealized Midstream Value Embedded Within RICE for a detailed explanation

11 The Premier Appalachian Energy Company UPSTREAM (E&P) ~248,000 acres in the Marcellus and Utica cores Belmont, Washington and Greene Counties in PA and OH OH WV PA ~1,100 locations with ~95% IRRs (1) 2017E net production = 1.3 Bcfe/d RICE MIDSTREAM HOLDINGS ~162,000 acres dedicated by RICE, GPOR, CNX Rice Olympus Midstream - central Belmont, 100% owned by RICE Strike Force Midstream eastern Belmont and central Monroe, 75% owned by RICE 2017E EBITDA (2) = $90MM 4Q16 throughput = 904 MDth/d RICE MIDSTREAM PARTNERS PA Gathering + PA and OH Water Services RICE subsidiary owns 28% of LP Units, 100% of GP + IDRs ~215,000 acres dedicated by RICE and EQT 2017E EBITDA (2) = $193MM 4Q16 throughput = 1.2 MMDth/d 2017E 20% distribution growth + 1.4x coverage 1. Marcellus and Utica economics assume E&P is burdened by 50% of the gathering and compression fee and 50% of water completion fees (Rice s direct subsidiary, REO, owns a 26% LP interest in RMP, 100% of Rice Olympus Midstream and 91.75% of RMP IDRs). Strip pricing as of February 10, 2017 based on weighted average of undeveloped locations; estimated well costs of $875 per lateral foot and $1,235 per lateral foot in the Marcellus and Utica, respectively. Assumes EURs of 15.1 Bcf and 21.0 Bcf in the Marcellus and Utica, respectively. 2. Please see "Non-GAAP Financial Measures" for a description of Adjusted EBITDA. 11

12 2016 Results and 2017 Guidance 12

13 Ad(Vantage) RICE: A Track Record of Doing What We Say We ll Do 2014 (IPO) (1) Net Production (MMcfe/d) % Beat Guidance E&P Opex ($/Mcfe) $1.07 $1.00 $0.98 3% E&P Capex ($MM) $830 $740 $686 7% Net Acres Added ~51,000 ~7,000 ~100,000 RMH Throughput (MDth/d) % RMH Capex ($MM) Note: Creative headline inspiration courtesy of CapitalOne. E&P operating expense includes lease operating, gathering and compression, firm transportation and production taxes. 1. Percent beat based on midpoint of 2016 guidance. 13 $248 $105 25%

14 2017 Guidance: Core Investments, High Growth and Low Leverage E&P - $1,035MM D&C Budget 1,290 1,355 net production (~93% Appalachia, ~60% reported YoY growth, ~45% organic YoY production growth) Budget assumes 10-15% service cost inflation ~90% hedged in 2017 at weighted average NYMEX floor price of $3.24/MMBtu Exit 2017 E&P leverage below 2.0x Funded primarily with cash flow Budget ($MM) Funding (%) (3) $1,035 $150 $300 $585 Non-Op Utica Operated Utica Marcellus 30% 70% Cash Projected Cash Flow (4) RMH - $315MM Budget (1) $85 95MM EBITDA (1)(2) (~90% YOY EBITDA growth) Budget primarily composed of long-term investments in gathering trunklines and compression Exit 2017 RMH leverage of ~2.25x $315 $75 $ Gathering Laterals Trunkline and Compression 55% 15% 10% 20% Credit Facility Cash LP + IDRs (5) Projected Cash Flow (4) 1. RMH capital budget and Adjusted EBITDA includes our 75% proportional ownership in Strike Force. Giving effect to Gulfport Midstream s 25% ownership interests of Strike Force, we expect a range of $95 105MM for 2017 Adjusted EBITDA. 2. Please see "Non-GAAP Financial Measures" for a description of Adjusted EBITDA. 3. Projected funding excludes potential drop down proceeds. 4. Projected cash flow based on strip pricing as of February 10, 2017 and 2017 guidance assumptions. 5. Based on 20% estimated distribution growth. 14

15 2017 Detailed Guidance E&P Guidance RMH Guidance (1) Net Wells Spud Online Net Production (MMcfe/d) Operated Marcellus Appalachia 1,205-1,265 Operated Ohio Utica Barnett Non-operated Ohio Utica 10 5 Total Net Production 1,290-1,355 Total Net Wells % Natural gas 99% % Operated 94% % Marcellus 65% % Utica 28% Lateral Length (ft.) of Wells Spud Online Operated Marcellus 8,500 8,000 Pricing Operated Ohio Utica 10,500 9,000 FT Fuel & Variable (Deduction) $0.11 Non-operated Ohio Utica 9,500 8,500 Heat Content (Btu/Scf) Marcellus 1,050 Utica 1, Capital Budget ($ in millions) E&P Operating Costs ($/Mcfe) Operated Marcellus $585 Lease Operating Expense $ $0.18 Operated Ohio Utica $300 Gathering and Compression $ $0.47 Non-operated Ohio Utica $150 Firm Transportation Expense $ $0.27 Total Drilling & Completion $1,035 Production Taxes and Impact Fees $ $0.06 Land $225 Total Operating Costs $ $0.98 Total E&P $1,260 E&P G&A ($ in millions) $85 - $ Capital Budget ($ in millions) Gas Gathering and Compression $315 G&A ($ in millions) Gas Gathering and Compression $15 - $20 Adjusted EBITDA (2) ($ in millions) Gas Gathering and Compression $85 - $95 Operating Statistics Gathering Throughput (MDth/d) 1,125-1,185 RMP Guidance 2017 Capital Budget ($ in millions) Gas Gathering and Compression $255 Water Services 0$60 Total RMP $315 Est. Maintenance Capital ($ in millions) $18 G&A ($ in millions) $25 - $30 Adjusted EBITDA (2) ($ in millions) Gas Gathering and Compression $145 - $155 Water Services $40 - $45 Total Adjusted EBITDA $185 $200 % Third Party 15% - 20% Distributable Cash Flow (2) ($ in millions) $160 - $170 Average DCF Coverage Ratio (2) 1.35x x % Distribution Growth 20% Operating Statistics Gathering Throughput (MDth/d) 1,315-1,380 Water Volumes (MMGal) 1,300-1, Does not assume any drop downs. RMH capital budget, G&A and Adjusted EBITDA includes our 75% proportional ownership in Strike Force. Giving effect to Gulfport Midstream s 25% ownership interests of Strike Force, we expect a range of $95 105MM for 2017 Adjusted EBITDA. 2. Please see "Non-GAAP Financial Measures" for a description of Adjusted EBITDA and Distributable Cash Flow.

16 16 E&P

17 100% Core E&P Portfolio in Appalachia with Consistent, Attractive Returns PENNSYLVANIA 1,200 1,000 92% 861 Net Locations and IRRs (1)(2) 1,102 85% 90% OHIO % 60% 600 Utica ~63,000 net acres Marcellus ~185,000 net acres ~105,000 stacked Utica acres 100% of Appalachian assets in the cores of the Marcellus and Utica Added ~100,000 net acres in 2016 for a total leasehold position of ~248,000 core net acres Highly concentrated, contiguous position affords longer laterals ~10% variability in well performance across leasehold Projecting 9,000 foot average laterals spud in % Marcellus OH Utica Dry OH Utica Wet Total IRRs Extensive inventory of high returning locations ~255 net producing wells, ~1,100+ net locations remaining Potential upside from ~228 PA Utica undeveloped locations Returns improved from 50% to ~85% in 2016 at $3.00 HHUB (2) Average F&D cost of ~$0.50/Mcf 1. Net undeveloped locations as of 12/31/16. See slide entitled Additional Disclosures on detail regarding RICE s methodology for the calculation of locations. 2. Marcellus and Utica economics assume E&P is burdened by 50% of the gathering and compression fee and 50% of water completion fees (Rice s direct subsidiary, REO, owns a 26% LP interest in RMP, 100% of Rice Olympus Midstream and 91.75% of RMP IDRs). Assumes $3.00 NYMEX; estimated well costs of $ 875 per lateral foot and $1,235 per lateral foot in the Marcellus and Utica, respectively. Assumes EURs of 15.1 Bcf and 21.0 Bcf in the Marcellus and Utica, respectively % 0%

18 Achieving Shale Scale With 100% Core Appalachia Acreage Large, concentrated core acreage position in Appalachia Well Results Heat Map ($ Revenue/Well/Year) Utica Core Marcellus Cores RICE Core Bottom 80 th Percentile 100% of RICE inventory in the Appalachian core v. peers average of only ~60% core inventory Core Appalachian wells deliver 200% more production than non-core Peer Acreage Map 100% Rice Energy 85% 80% 80% Peer Non Core Acreage 60% 45% 45% 35% Peer Core Acreage RICE Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 7 Core acreage Non-core acreage Note: Core outlines based upon state production data and revenue per well ($2.50 dry gas and $45 condensate) and RICE estimates of peer acreage positions based on investor presentations. Peers include AR, CNX, COG, EQT, GPOR, RRC and SWN. 18

19 19 Well Results Driven by Being a Technical Leader Drilling Lateral Placement Pioneered lateral targeting proficiency in the Marcellus in 2011 using rotary steerable tools Every RICE operated well is geosteered by our 24/7 team in RICE s headquarters Lateral Length Drilled first 10,000 ft. lateral in 2013 RICE laterals ever since have consistently been on average 2,000-3,000 ft. longer than peers Completions Completion Size Choke Management Pumped ~1,900 lb/ft. on first Marcellus well (2010) Pumped ~2,900 lb/ft. on first Utica well (2014) Most peers design just now catching up to what we adopted 8 years ago Gen 4 is our Gen 1 Stage Length 250 ft. stage length on first Marcellus well 160 ft. stage length on the 5 th well ft. stage lengths ever since Production The Future Innovation Still in Full Force In 2010, mapped relationship between flow rate (normalized for lateral length) and pressures to determine current choke management practice RICE completed ~420 value driving initiatives in 2016 related to project cost reductions and productivity improvements We are actively working through >200 new initiatives 10,000 8,000 6,000 4,000 2, ,000 1, Lateral Length (ft.) Proppant Intensity (lbs/ft.) Rice Energy Stage Length (ft.) Rice Energy Peers

20 Proven, Repeatable Well Design Drives Industry-Leading Results RICE s industry-leading well results are evident in 1-4 year cumulative production per well 100% of RICE s expected future Appalachian activity is focused within its concentrated, core acreage position SW Appalachia - Marcellus SW Appalachia - Utica 1,000,000 1,000,000 RICE Utica RICE Marcellus Cumulative Production per 1,000 (Mcfe) 800, , , , , , , ,000 RICE Utica RICE Marcellus Industry Marcellus + Utica ,000 1,500 0 Days Online ,000 1,500 Note: Data for RICE based on actuals through 12/31/16, peer data based on Pennsylvania Department of Environmental Protection production reports through 11/30/16 and Ohio Department of Natural Resources report through 9/30/16. 20

21 Track Record of Low-Cost Growth MARCELLUS D&C COSTS ($/FT.) (1) UTICA D&C COSTS ($/FT.) (1) $2,590 $1,270 $1,220 $800 $875 $1,715 $1,205 $1, E E NET WELLS TURNED TO SALES AND LATERAL LENGTHS (2) 8,200 9,800 9,200 9,000 7,300 7,300 7,100 8, NET PRODUCTION (MMCFE/D) , E PA OH E well costs assume 10 15% service cost increase. Hedged ~60% of 2017E service costs mitigating further cost escalation. 2. Net wells turned to sales including non-operated Ohio Utica wells and corresponding operated horizontal lateral lengths E

22 Highly Visible Production and Cash Flow Growth Table is set for projected RICE production growth to ~2 Bcfe/d and peer-leading cash flow per share growth ~60% volume hedged through 2019E production providing downside protection VISIBLE GROWTH PROTECTED BY HEDGES 2017E E CASHFLOWPER SHAREGROWTH 2, % 38% Production (MMcfe/d) and EBITDA (1) ($MM) 1,500 1, % 70% 30% % 20% 10% 20% 18% 15% 13% 13% Peer Median 7% 7% E 2018E 2019E (1) EBITDA Production % Hedged Consensus EBITDA Consensus Production Note: Peer data and RICE consensus estimates based on Factset as of February 15, Peers include AR, CNX, COG, EQT, GPOR, RRC and SWN. 1. Please see "Non-GAAP Financial Measures" for a description of Adjusted EBITDA and related reconciliations to comparable GAAP financial measures. 22 RICE Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 7 '17E - '19E CAGR Peer Median

23 Significant Cost Structure Improvements and Still Declining Lowest cost structure in the peer group with expected improvement from increased scale RICE CONSOLIDATED OPERATING COSTS ($/MCFE) 2017E COST STRUCTURE VS. PEERS ($/MCFE) $1.80 Cost structure will continue to decline as production grows $2.50 $2.13 $ $0.51 $0.57 $0.05 $0.41 $1.54 $0.43 $0.43 $0.04 $0.42 $1.35 $0.33 $0.39 $0.05 $0.41 $1.12 $0.23 $0.36 $0.04 $0.32 Cost Structure ($/Mcfe) $2.00 $1.50 $1.00 $.50 $1.12 $1.18 $1.33 $1.64 $1.72 $ E Net Production (Bcfe/d) $0.26 $0.22 $0.17 $ E (1) RICE RICE Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 7 - LOE G&T Taxes G&A Interest LOE G&T Taxes G&A Interest Production(Bcfe/d) Note: Peer data based on Factset as of February 15, Peers include AR, CNX, COG, EQT, GPOR, RRC and SWN estimates based on guidance and interest based on Factset as of February 15, Consolidated figures eliminate intercompany charge of gathering and compression. 23

24 Midstream 24

25 RMH - Ohio Gathering: Core System with High Growth in the Utica Belmont Legend RICE Acreage OH Gathering Pipeline Significant RMH EBITDA (1) Growth ($MM) $100 (2) Strike Force JV AMI GPOR Dedicated to RICE Monroe RICE Acreage Dedicated to 3 rd Party OH PA WV ~162,000 core dedicated acres with ~75% from high-quality 3 rd party customers (GPOR & CNX) Systems expected to be monetized into RMP 75% ownership of Strike Force JV (GPOR 25%) 1. Please see "Non-GAAP Financial Measures" for a description of Adjusted EBITDA and related reconciliations to comparable GAAP financial measures. 2. Giving effect to Gulfport Midstream s 25% ownership interests of Strike Force, we expect a range of $95 105MM for 2017 Adjusted EBITDA. 25 $ E

26 RMH - GP Holdings: Rapid Cash Flow Growth RMH owns 26% of RMP LP units outstanding and 91.75% of IDRs RMP s expected 20% distribution growth drives a 5x / 50% CAGR in GP Holdings cash flow in 5 years One of the only E&P companies in the industry with an unmonetized GP IDR and LP Distribution Potential ($MM) $175 $130 $115 $90 $80 $60 $50 $25 $20 $35 $5 $20 $24 $30 $35 $40 $25 $50 $ E 2018E 2019E 2020E 2021E LP Distributions Note: Assumes 20% distribution growth and units outstanding remain flat. Net to Rice s 91.75% interest in GP Holdings. 26 IDR Distributions

27 RMP: Core System and Execution Drives High Distribution Growth OH WV PA Belmont Washington Significant RMP EBITDA Growth (1) ($MM) $193 Water $43 Greene Gathering & Compression Legend RICE Acreage Beaver 3 rd Party Dedicated to RMP RMP Gathering Pipeline RMP Water Interconnects RMP Water Pipeline GPOR Water Dedication $158 $150 ~215,000 acres dedicated in core of dry gas Marcellus Primary customers: RICE and EQT 20% distribution growth expected through % of cash flow supported by long-term, fee-based contracts Beginning trunkline buildout in Greene County, PA on Vantage and western Greene acreage 2017E budget funded through cash flow + cash on hand and debt 2 nd best performing MLP in the AMZ in 2016 (2) 1. Please see "Non-GAAP Financial Measures" for a description of Adjusted EBITDA and related reconciliations to comparable GAAP financial measures. 2. Based on Factset as of February 15, $ E

28 Unparalleled Midstream Growth RICE has positioned itself as the premier Appalachian core dry gas midstream player 3,000,000 4Q 2016 throughput of ~2,108 MDth/d through RMH and RMP midstream systems RMP System: 1,203 MDth/d (24% 3 rd Party) RMH System: 904 MDth/d (59% 3 rd Party) 2017E Throughput 2,500,000 2,000,000 Dth/d 1,500,000 1,000, ,000 Jan '14 Jan '15 Jan '16 Jan '17 RMP - Rice Operated (PA) RMP - 3rd Party (PA) RMH - 3rd Party (OH) RMH - Rice (OH) 28

29 Significant Unrealized Midstream Value Embedded Within RICE ($ in millions) IDRs Estimated Distributions (Avg '17-'19) (1) $27 Multiple 25.0x 35.0x Estimated Distributions (Avg '17-'19) $675 - $950 LP Units Estimated Distributions (Avg '17-'19) (1) $35 Yield 5.0% 4.0% Estimated Value $700 - $875 Total GP Holdings $1,375 - $1,825 Total Ohio Midstream $1,100 - $1,400 Total Potential RMH Value $2,475 - $3, Net to Rice s 91.75% interest in GP Holdings. Assumes 20% distribution growth. 29

30 Financial and Strategic Position 30

31 Healthy Balance Sheet Protected by Strong Hedge Book LOW LEVERAGE (1) Strong balance sheet across enterprise Expect to exit 2017 at 2.0x consolidated leverage vs. peer average (2) of 3.1x HEDGE SUMMARY ~90% of 2017E production hedged at $3.24/MMBtu NYMEX ~93% of 2017E production covered by FT or basis hedging ~70% of 2018 (consensus) production (2) hedged at $3.04/MMBtu NYMEX 1.8x 1.1x 1.5x 1,400 1,200 1, $3.24 1,246 1,259 $3.05 $3.04 $2.96 $2.87 $2.87 $2.96 $2.96 $3.20 $3.00 $2.80 $ $ $2.20 $ x Rice E&P RMH RMP Consolidated YE2016 Net Debt / LTM Adj. EBITDAX 200 $1.80 $ Hedged Volume NYMEX Avg. Wtd. Floor Price Total Avg. Wtd. Floor Price 1. Please see Non-GAAP Financial Measures for a description of Adjusted EBITDAX, Further Adjusted EBITDAX, Adjusted EBITDA and related reconciliations to comparable GAAP financial measures. 2. Based on Factset as of February 15,

32 Meaningful Takeaway Capacity Expected to Outpace Supply Growth Expect ~18 Bcf/d incremental takeaway capacity in-service by January 2020 to provide significant improvement in local pricing Bcf/d ~10 Bcf/d of expected takeaway received FERC approval or is currently under construction We don t expect Appalachia to grow the required 4+ Bcf/d annually to meet FT capacity Production Above FT = Stressed Basis Pricing Current Appalachia Production Appalachian Basin Production Growth By Rig Count Strip Pricing Improved Dramatically Since Vantage Acquisition M2 Basis Oct. 16 ($1.39) ($0.93) ($0.76) ($0.66) M2 Basis Feb. 17 ($0.80) ($0.62) ($0.57) ($0.52) % Returns at Strip Pricing (1) with Attractive Basis Outlook Risk/Reward 32 Production below FT = Improved Basis Pricing Supply Scenarios 125 Rigs / 38 Bcfd 110 Rigs / 35 Bcfd 85 Rigs / 30 Bcfd 65 Rigs / 26 Bcfd 60 Rigs-Current Rig Count 50 Rigs / 22 Bcfd 1. Marcellus and Utica economics assume E&P is burdened by 50% of the gathering and compression fee and 50% of water completion fees (Rice s direct subsidiary, REO, owns a 26% LP interest in RMP, 100% of Rice Olympus Midstream and 91.75% of RMP IDRs). Strip pricing as of February 10, 2017 based on weighted average of undeveloped locations; estimated well costs of $875 per lateral foot and $1,235 per lateral foot in the Marcellus and Utica, respectively. Assumes EURs of 15.1 Bcf and 21.0 Bcf in the Marcellus and Utica, respectively.

33 RICE Trades at a Discount to Peers Despite Most Attractive Attributes RICE trades at a discount to peers despite core assets, high growth, low leverage and significant midstream value Financially positioned like a large cap peer, but still growing rapidly 10.0x Of the six criteria below, only one other company checks half the boxes 9.0x 8.0x 9.3x 8.6x 8.2x 50% 45% 40% Consensus `18E EV/EBITDA `17E - `18E Production Growth 7.0x Series1 6.0x Series2 5.0x 4.0x 36% 5.2x 5.6x 6.1x 6.2x 31% 23% 6.6x 35% 30% 25% 20% 3.0x 2.0x 15% 18% 17% 18% 15% 10% 1.0x 8% 5% 0.0x >20% 2018E Production Growth >245,000 Core Dry Acres >50% Hedged in 2018 <2.0x YE 2017 Leverage (1) Retained Midstream (2) GP Ownership RICE Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 7 Note: Peers include AR, CNX, COG, EQT, GPOR, RRC and SWN. Based on Factset Research and management estimates as of February 15, Market data as of February15, Leverage represents ratio of net debt to Adjusted EBITDAX. Please see Non-GAAP Financial Measures for a description of Adjusted EBITDAX and Further Adjusted EBITDAX. 2. Retained midstream includes assets owned by the MLP sponsor. 33 0%

34 Economic Assumptions: Improved Cost Structure and Lateral Lengths Feb `16 Feb `17 % Change Net Locations 487 Marcellus / 215 Utica 702 Total 861 Marcellus / 241 Utica 1,102 Total 57% Lateral Length 7,000 Marcellus 9,000 Utica 8,000 Marcellus 9,000 Utica 14% - % Net Horizontal Feet (MM ft) 2.8 Marcellus / 1.5 Utica 4.3 Total 5.7 Marcellus / 1.7 Utica 7.5 Total 74% D&C Costs ($/lateral ft) $1,150 Marcellus $1,450 Utica $875 Marcellus $1,235 Utica 24% 15% Operating Costs ($/Mcfe) (1) $1.14 $ % Single Well IRRs (2) ~49% Marcellus ~47% Utica Dry ~90% Marcellus ~70% Utica 88% 53% Single Well PV-10 (2)(3) $7.6MM Marcellus $8.2MM Utica Dry $9.6MM Marcellus $9.9MM Utica 26% 21% 1. Operating costs include lease operating, gathering and compression, firm transportation and production taxes. 2. Marcellus and Utica economics assume E&P is burdened by 50% of the gathering and compression fee and 50% of water completion fees (Rice s direct subsidiary, REO, owns a 26% LP interest in RMP, 100% of Rice Olympus Midstream and 91.75% of RMP IDRs). Assumes $3.00 NYMEX; estimated well costs of $875 per lateral foot and $1,235 per lateral foot in the Marcellus and Utica, respectively. Assumes EURs of 15.1 Bcf and 21.0 Bcf in the Marcellus and Utica, respectively. 3. Please see PV-10 Reconciliation for a related reconciliation of PV-10 to the comparable GAAP financial measure. 34

35 Stock Performance Track Record: Top Performing Since IPO 100% core E&P and midstream assets + differentiated execution and strategy drive outperformance 80% 60% Outperformed 2 nd peer by ~35% and median by ~60% 40% 20% 0% (20%) (40%) (60%) (80%) RICE 3% HHUB (40%) WTI (45%) Peers (39%) (64%) (100%) Jan '14 Jan '15 Jan '16 Jan '17 Note: Peers include AR, CNX, COG, EQT, GPOR, RRC and SWN. 35

36 The Premier Appalachian Energy Company % of Leasehold in Core of Marcellus and Utica Differentiated Technical Approach Has Led to Industry Leading Well Results High Returning Wells Driving Rapid Production Growth Significant Midstream Value Strong Balance Sheet and Hedge Position Nimble and Incentivized Management and Technical Teams Top-Tier Growth With Attractive Risk-Adjusted Return Profile

37 Appendix 37

38 RICE and RMP Market Snapshot ($ millions, except per share data) Rice Energy Inc. (NYSE: RICE) Employee Ownership ~18% (1) Shares Outstanding (MM) 243 Price $21.12 Market Capitalization $5,123 Cash 470 Preferred Equity 383 Revolving credit facilities % Senior notes due % Senior notes due Enterprise Value $6,558 Rice Midstream Partners LP (NYSE: RMP) ($ millions, except per unit data) Common Units 73 Subordinated Units 29 Total Units Outstanding (MM) 102 Price $24.80 Market Capitalization $2,532 Cash 22 Revolving credit facility 190 Enterprise Value $2,700 Distribution/Unit $ Yield 4.04% Website: Investor Contact: Julie Danvers Website: Investor Contact: Julie Danvers Note: Share and unit price as of February15, Share count, unit count and balance sheet data as of December 31, Presented as of December 31, 2016 and inclusive of the 40,000,000 Rice Energy Operating LLC common units immediately convertible into 40,000,000 shares of Rice Energy Inc. common stock. 38

39 RICE and RMP Organizational Structure EIG Managed Funds $1.45B E&P Borrowing Base 8.25% common equity interest 100% Series B Preferred Equity ($375MM invested) 91.75% common equity interest Rice Midstream DE Holdings LLC 100% ownership $300MM Credit Facility + $100MM Accordion Feature 100% equity interest 75% equity interest Rice E&P GP Holdings (IDRs and LP Interest) RMP GP (non-economic) Rice Olympus Midstream (OH Gathering) Strike Force Midstream (GPOR JV) 28% LP interest & 100% of IDRs ROFO Assets Public Unitholders (72% LP Interest) $850MM Credit Facility 100% interest PA Gathering PA Water OH Water Ownership percentages as of December 31,

40 2017 D&C Budget Maintains Strong Balance Sheet while Investing in budget and guidance: Capex: $1,035MM Production: Bcfe/d $400MM of maintenance to hold production flat ~$635MM additional capex generates ~80 wells in progress that will drive meaningful growth in % core development creates unique combination of best-in-class growth while maintaining a strong balance sheet Maintenance drilling and completion activity $400 Drilling and completing wells that come online in 2017 $ Budget Build pads, and drill and complete wells to be turned to sales in $1,035 $530 $105 $105 $400 $400 $400 $530MM drives production $505MM drives 2017 production ~40% YoY Growth Flat Exit to Exit ~45% YoY Organic Growth ~ 45% YoY Organic Growth 2017E Production, MMcfe/d 1,145 1,290 1,355 1,290 1,355

41 Meaningful Value Derived from Developed Drilling Locations PROVED RESERVES (BCFE) PV-10 (1) ($MM) Proved Undeveloped Proved Developed 4,005 Proved Undeveloped Proved Developed $3,231 $1,019 1, , ,015 1,827 2,178 $1,744 $600 N.A. $886 $85 $1,181 $246 $801 $935 $1,568 $269 $1,299 $2,212 SEC SEC SEC SEC Strip SEC Strip SEC Strip ACREAGE NET LOCATIONS 248,000 1, , ,000 55,000 56,000 63, , ,000 92, Marcellus OH Utica 1. Please see PV-10 Reconciliation for a related reconciliation of PV-10 to the comparable GAAP financial measure Marcellus OH Utica

42 Diverse Market Exposure Provides Takeaway Capacity to Multiple Markets Appalachia takeaway commitments provides to access various markets in North America Midwest (MDth/d) 2017E 2018E Midwest Markets Gulf Coast (MDth/d) 2017E 2018E Canada (MDth/d) 2017E 2018E TAKEAWAY PORTFOLIO Note: Conversion of Dth to Mcf assumes 1,050 Btu factor. 1. Source: Company Filings, TPH Estimates. Canadian Markets Gulf Coast Demand/Exports by 2020: +12 to 15 Bcf/d (1) Gulf Coast Markets TCO (MDth/d) 2017E 2018E Appalachian Markets Northeast (MDth/d) 2017E 2018E RICE Acreage 4,000 3,500 3,000 2,500 2,000 1,500 1, EXPECTED TAKEAWAY CAPACITY (MDTH/D) Jan '15 Jan '16 Jan '17 Jan '18 Jan '19 Jan '20 Jan '21 Illustrative Takeaway Volume Range Expected Takeaway Capacity RICE FIRM CAPACITY COMMITMENTS Project Pipeline Expected In-Service Date Volume (MDth/d) Market TEAM South TETCO In-Service 270 Gulf Coast Rockies Express REX In-Service 225 Midwest/Canada/Gulf Coast Westside Expansion CGT/TCO In-Service 125 TCO, Gulf Coast Union Town to Gas City TETCO In-Service 87 Midwest/Gulf Coast OPEN TETCO In-Service 50 Gulf Coast Access South TETCO 17-Nov 320 Gulf Coast ET Rover Rover 17-Nov 100 Canada Expected Total Capacity 1,177 ~60% of expected firm capacity is already in service; remaining 40% expected in service by end of 2017

43 Basis Exposure & Realized Pricing PRICING COMMENTARY FT portfolio covers ~60% of 2017E takeaway volumes, decreasing to ~40% in 2020E ~93% of 2017E gas is either transported out of basin or hedged locally to protect against anticipated weak 2017E basis ~90% of 2017E production hedged at $3.24/MMBtu NYMEX ~75% of 2018E gas (based on consensus production) is either transported out of basin or hedged locally ~60%+ in 2020E exposed to local markets when differentials are expected to tighten to ~$0.55 (1) Improving FT demand expense leads to enhanced low-cost margins Mitigated local basis differential risk through basis hedges 42% 42% 9% 9% 12% 13% 38% 36% EXPECTED BASIS EXPOSURE 53% 7% 10% 29% 47% 47% 48% 7% 8% 8% 8% 10% 4% 39% 35% 40% 1Q17E 2Q17E 3Q17E 4Q17E 2017E 2018E Gulf Coast TCO Midwest / Dawn DTI / M2 / M3 EXPECTED REALIZED PRICING 1Q17E 2Q17E 3Q17E 4Q17E 2017E 2018E NYMEX Henry Hub Strip ($/MMBtu) (1) $3.45 $3.19 $3.32 $3.41 $3.34 $3.09 Plus/Less: Average Basis Impact (0.26) (0.39) (0.57) (0.36) (0.40) (0.29) Less: Firm Transportation Fuel & Variables (0.12) (0.11) (0.09) (0.11) (0.11) (0.09) Plus: BTU Uplift (MMBtu/Mcf) Pre-Hedge Realized Price ($/Mcf) $3.30 $2.88 $2.83 $3.14 $3.02 $2.89 Plus: Realized Hedging Gain/Loss ($/Mcf) (0.29) (0.05) (0.16) (0.22) (0.18) (0.08) Post Hedged Realized Price ($/Mcf) $3.01 $2.83 $2.67 $2.92 $2.84 $2.81 FT Demand Expense ($0.28) ($0.26) ($0.21) ($0.27) ($0.26) ($0.29) FT Expense (Fuel & Variables + Demand) ($0.40) ($0.37) ($0.31) ($0.38) ($0.37) ($0.38) FT Expense + Basis + BTU Uplift ($0.43) ($0.57) ($0.70) ($0.55) ($0.58) ($0.49) 1. Strip pricing as of February 10,

44 Firm Transportation and Basis Exposure $1.00 $0.50 Cost of firm transportation must be factored into realized pricing comparisons across Appalachian peers 2018 strip basis has tightened $0.30 since October 2016, highlighting the value of RICE s balanced FT portfolio $0.70 $0.10 $ Appalachian Basis Assumption = ($0.80) Strip $0.80 $0.80 $0.43 $0.37 $0.80 $1.00 $0.50 $0.80 $0.10 $ Appalachian Basis Assumption = ($0.50) App Basis Strip ($0.62) $0.69 $0.63 $0.29 $0.34 $0.62 $0.50 $1.00 $0.50 Appalachian Basis Assumption = ($0.50) $0.90 App Basis Strip ($0.57) $0.10 $ $0.71 $0.64 $0.34 $0.30 $0.57 $0.50 Full FT RICE No FT Chart illustrates all-in FT + Basis expense (pre-hedge) for Full FT RICE No FT 1) Producer with 100% of volumes covered under firm transportation ( Full FT ) 2) RICE Firm Transportation Expense (Demand + Fuel & Variables) 3) Producer with no FT that is 100% exposed to local Appalachian prices ( No FT ) Wtd Average Basis Full FT RICE No FT Full FT has a low all-in expense in 2017 while Appalachian basis differentials are weak, but as new and expensive FT projects come online in 2018/2019, Appalachian basis will strengthen lowering RICE s cost structure For those completely covered by FT (or long FT), their relative cost structure will be fixed at higher levels than peers Note: Based on management estimates. Strip pricing as of February 10, 2017 based on weighted average of undeveloped locations 44

45 Attractive Single Well Economics RICE continues to drive down D&C and operating costs to maximize returns Inventory currently generates ~95% returns at strip; HHUB PV-10 breakevens of ~$1.75 HHUB (1) DRY GAS SINGLE WELL ECONOMICS 206% 142% 166% 92% 115% 53% 72% 39% $2.50 $3.00 $3.50 $4.00 MARCELLUS NYMEX ($/MMBtu) Net Locations (2) HHUB PV-10 Breakeven ($/MMBtu) $1.67 $1.90 Note: Marcellus and Utica economics assume E&P is burdened by 50% of the gathering and compression fee and 50% of water completion fees (Rice s direct subsidiary, REO, owns a 26% LP interest in RMP, 100% of Rice Olympus Midstream and 91.75% of RMP IDRs). Assumes long-term well costs of $875 per lateral foot and $1,235 per lateral foot in the Marcellus and Utica, respectively. Assumes EURs of 15.1 Bcf and 21.0 Bcf in the Marcellus and Utica, respectively. 1. Strip pricing as of February 10, Excludes ~47 wet OH Utica net undeveloped locations and ~228 dry gas PA Utica net undeveloped locations. 45 UTICA

46 Marcellus and Utica Single Well Type Curves MMcf/d MARCELLUS SINGLE WELL TYPE CURVE Restricted Rate Years Marcellus EUR (Bcf/1,000') 2.16 Lateral Length 8,000 EUR (Bcf) 17.3 Interwell Spacing 750 Choke (MMcf/d per 1,000') 1.5 Flat Time (Days) year Cum. (Bcf) year Cum. (Bcf) year Cum. (Bcf) year Cum. (Bcf) 12.2 IRR ($3.00 HHub) 92% PV-10 ($MM) ($3.00 HHub) $9.6 MMcf/d OHIO UTICA SINGLE WELL TYPE CURVE Restricted Rate Years OH Utica EUR (Bcf/1,000') 2.33 Lateral Length 9,000 EUR (Bcf) 21.0 Interwell Spacing 1,000 Choke (MMcf/d per 1,000') 1.8 Flat Time (Days) year Cum. (Bcf) year Cum. (Bcf) year Cum. (Bcf) year Cum. (Bcf) 15.2 IRR ($3.00 HHub) 72% PV-10 ($MM) ($3.00 HHub) $9.9 Note: See appendix for summary of assumptions used to generate single well IRRs. 46

47 Economics IRR 100% 90% 80% 70% 60% 50% 40% 30% 20% 10% 0% 92% $9.6 PV10 & IRRS (1)(3) Economics Adjusted for Gathering Ownership at $3.00 HHUB & $27/bbl NGLs $9.9 72% $2.3 19% $12.0 $10.0 $8.0 $6.0 $4.0 $2.0 PV10 ($mm) 47 ECONOMIC ASSUMPTIONS Marcellus Utica Dry Utica Wet Type Well Assumptions Spacing 750 1,000 1,000 Lateral Length 8,000 9,000 9,000 GAS EUR (Bcf/1,000') Condensate EUR (Bcf/1,000') 0.07 NGL Yield (bbls/mmcf) 26 Gas Shrink 13% Pre-Processed EUR (Bcfe) Post-Processed EUR (Bcfe) % Gas 100% 100% 82% Heat Content (Btu/Scf) 1,050 1,080 1,175 Initial Choke (MMcf/d per 1,000') Flat Period (days) (2) D&C Assumptions (2) D&C ($mm) $7.0 $11.1 $11.1 D&C per Lateral ($ per foot) $875 $1,235 $1,235 Operating Expenses (NRI Gas) Fixed Operating Expenses ($/well/month) $6,378 $6,378 $6,378 Variable Operating Expenses ($/mcf) $0.11 $0.11 $0.11 All-in Operating Expenses ($/mcf) $0.17 $0.16 $0.17 Other Costs/Expenses (NRI Gas) Well Impact Fee? Yes No No Severance Taxes ($/mcf) $0.04 $0.04 Avg. Royalty 17% 20% 20% Gathering, Processing and Compression (NRI Gas) Gathering, Compression, Processing Fees ($/dth) $0.45 $0.46 $1.01 NGL Fractionation and Transport ($/bbl) $5.08 Adjusted Gathering and Compression Fees ($/dth) $0.22 $0.23 $1.01 Midstream Adjustment 50% 50% Firm Transportation and Basis (NRI Gas) Basis + Fuel (Variable) % of Gas Price (13%) Wtd. Avg Reservation Fee + Commodity Fee (Fixed) $/dth ($0.23) All-In Assuming $3.00 HHUB (NRI) ($0.63) Inventory Net Undeveloped Locations NRI Undeveloped Horizontal Feet (mm ft) Marcellus OH Utica Dry OH Utica Wet Economics Summary (Adjusted for Ownership of Midstream In Each Area, $3.00 HHUB, $27/bbl NGLs) PV-10 Single Well $9.6 $9.9 $2.3 IRR PV10 IRR 92% 72% 19% Payback (Months) Breakeven Realized ($/dth) $1.67 $1.90 $ Economics assume E&P is burdened by 50% of the gathering and compression fee and 50% of water completion fees (RICE owns a 26% LP interest in RMP, 100% of Rice Olympus Midstream and 91.75% of RMP IDRs). 2. D&C costs are fully burdened by water completion fees of ~$50 per lateral foot in the Marcellus and ~$65 per lateral foot in the Utica. 3. Please see PV-10 Reconciliation for a related reconciliation of PV-10 to the comparable GAAP financial measure.

48 Hedging Summary RICE s gas will be marketed into 4 areas (1) Gulf Coast (ELA, M1) (2) TCO (3) Midwest (Chicago, Dawn) (4) Appalachia (M2, M3, & Dominion) ~60% of expected first quarter 2017 production transported out of Appalachian basin Our Gulf Coast firm transportation contracts deliver to markets in the Gulf Coast (ELA, M1) We hedge our Gulf Coast basis exposure opportunistically, but believe our Henry Hub NYMEX derivatives serve as a hedge against these indices which have historically traded within a narrow band of $0.05-$0.15 below Henry Hub 1. Includes the effect of basis hedges. 2. Wtd. avg. fixed price floor. 3. Assumes the mid-point of guidance. 48

49 Hedging Detail 49 All-In Fixed Price Derivatives 1Q17E 2Q17E 3Q17E 4Q17E 2017E 2018E 2019E 2020E 2021E NYMEX Natural Gas Swaps Volume Hedged (BBtu/d) Wtd. Avg. Swap Price ($/MMBtu) $3.42 $3.30 $3.21 $3.22 $3.28 $3.00 $2.95 $2.96 $2.89 NYMEX Natural Gas Collars Volume Hedged (BBtu/d) Wtd. Avg. Call Price ($/MMBtu) $3.28 $3.73 $3.73 $3.73 $3.64 $3.63 $3.52 Wtd. Avg. Floor Price ($/MMBtu) $4.17 $3.08 $3.08 $3.08 $3.30 $3.15 $3.00 NYMEX Natural Gas Calls Volume Hedged (BBtu/d) Wtd. Avg. Call Price ($/MMBtu) $3.50 $3.50 $3.50 $3.50 $3.50 $3.32 $3.55 $3.47 NYMEX Natural Gas Deferred Puts Volume Hedged (BBtu/d) Wtd. Avg. Net Floor Price ($/MMBtu) $2.50 $2.50 $2.51 $2.51 $2.50 $2.77 $2.80 Total NYMEX Index Derivatives NYMEX Volume Hedged (BBtu/d) ,078 1, NYMEX Volume Hedged Incl. Calls (BBtu/d) ,138 1,189 1,030 1, Swap, Collar & Put Floor ($/MMBtu) $3.57 $3.18 $3.13 $3.14 $3.24 $3.04 $2.96 $2.96 $2.89 WAHA Natural Gas Swaps Volume Hedged (BBtu/d) Wtd. Avg. Swap Price ($/MMBtu) $3.06 $3.07 $3.03 $3.11 $3.07 $3.01 $3.29 Basis Contract Derivatives 1Q17E 2Q17E 3Q17E 4Q17E 2017E 2018E 2019E 2020E 2021E Appalachian Basis Volume Hedged (BBtu/d) Wtd. Avg. Swap Price ($/MMBtu) ($0.81) ($1.12) ($1.22) ($1.10) ($1.09) ($0.69) ($0.59) ($0.55) ($0.55) Other Basis Volume Hedged (BBtu/d) Wtd. Avg. Swap Price ($/MMBtu) ($0.11) ($0.14) ($0.14) ($0.13) ($0.13) ($0.15) ($0.15) ($0.14) ($0.12) Total Basis Hedges (Financial + Physical) Volume Hedged (Bbtu/d) , Wtd. Avg. Swap Price ($/MMBtu) ($0.31) ($0.51) ($0.63) ($0.50) ($0.49) ($0.36) ($0.42) ($0.47) ($0.51) WTI Swaps Volume Hedged (BBtu/d) Wtd. Avg. Swap Price ($/MMBtu) $45 $45 $45 $45 $45 NGL Swaps Volume Hedged (BBtu/d) Wtd. Avg. Swap Price ($/MMBtu) $15 $15 $15 $15 $15 Dominion Natural Gas Swaps Volume Hedged (BBtu/d) Wtd. Avg. Swap Price ($/MMBtu) $2.33 $2.22 $2.17 $2.24 $2.24 $2.23 $2.34 Total Fixed Price Derivatives Total Fixed Volume Hedged (BBtu/d) 1,137 1,077 1,343 1,424 1,246 1, Total Fixed Volume Hedged Incl. Calls (BBtu/d) 1,197 1,137 1,403 1,484 1,306 1, Swap, Collar & Put Floor ($/MMBtu) $3.31 $2.99 $2.97 $2.98 $3.05 $2.87 $2.87 $2.96 $2.89

50 Fourth Quarter 2016 RICE Highlights Solid Fourth Quarter Results 1,145 4Q16 production (MMcfe/d) Net loss of $205MM, a 50% increase over 4Q15 Adjusted EBITDAX (1) of $202MM, a 53% increase over 4Q15 D&C well costs in the Marcellus and Utica to $775 and $1,100 per lateral foot, respectively, for wells drilled and completed in 4Q16 Average NYMEX differential of ($0.56)/MMBtu with 67% of production priced outside Appalachia 49% YoY organic production increase 1.5x Consolidated Leverage (1) Prolific Retained Midstream Growth Achieved record quarterly RMH gathering throughput of 904 MDth/d, a 180% increase over 4Q15 Increased total core acreage dedication to ~162,000 in Belmont and Monroe Counties, OH Strong Liquidity and Healthy Balance Sheet Increased borrowing base to $1.45B from $1B in Dec to incorporate the Vantage assets Strong 4Q16 liquidity position of $1.9B (2) to fund 2017 E&P and RMH capital needs 2017 Detailed Guidance D&C budget of $1,035MM driving projected ~45% organic (~60% reported) YoY production growth Majority of RMH budget of $315MM allocated to building out trunklines of Strike Force JV and installing compression in Ohio 1. Please see Non-GAAP Financial Measures for a description of Adjusted EBITDAX, Further Adjusted EBITDAX and related reconciliations to comparable GAAP financial measures. 2. Excludes Rice Midstream Partners LP. 50

51 Fourth Quarter & Full-Year 2016 Operational Highlights 51 MARCELLUS OPERATIONAL HIGHLIGHTS Turned to sales 18 gross (18 net) Marcellus wells in 4Q16 Avg. lateral length of ~6,700 feet 4Q16 Marcellus development costs averaged $775 per lateral ft. Drilled 7 net wells and completed 9 net wells In 2016, turned to sales 36 gross (36 net) Marcellus wells with an average lateral length of ~7,100 feet Expect 2017 well costs to average ~$875 per lateral foot UTICA OPERATIONAL HIGHLIGHTS 4Q16 Utica development costs averaged $1,100 per lateral ft. Drilled 9 net wells and completed 9 net wells In 2016, turned to sales 20 gross (13 net) operated Utica wells with an average lateral length of ~9,300 feet Turned to sales 38 gross (14 net) non-operated Utica wells Expect 2017 well costs to average ~$1,235 per lateral foot Net Wells Drilled Net Wells Completed Net Wells Turned to Sales Operated Marcellus Operated Ohio Utica Non-Operated Ohio Utica Strong Execution Drives Leading Edge D&C Costs and Well Results

52 RICE Fourth Quarter 2016 Consolidated Financial Summary Solid fourth quarter results supported by well-capitalized balance sheet and ample liquidity QUARTERLY HIGHLIGHTS 4Q16 production of 1,145 MMcfe/d, 49% organic increase from 4Q15 67% of 4Q16 production sold to premium, non-appalachian markets Increased borrowing base to $1.45B in December Three Months Ended December 31, 2016 Appalachia 1,072 Barnett 73 Total net production (MMcfe/d) 1,145 % Gas 99 % % Operated 88 % % Marcellus 61 % % Utica 32 % Actual ($MM) $/Mcfe NYMEX Henry Hub price ($/MMBtu) $2.98 Average basis impact ($/MMBtu) ($0.56) Firm transportation fuel & variables ($/MMBtu) ($0.12) Btu uplift (MMBtu/Mcf) $0.12 Pre-hedge realized price ($/Mcf) $2.42 Realized hedging gain ($/Mcf) $0.33 Post-hedge realized price ($/Mcf) $2.75 Lease operating $18 $0.18 Gathering, compression and transportation $39 $0.37 Production taxes and impact fees $6 $0.06 General and administrative $29 $0.32 Depletion, depreciation and amortization $121 $1.15 Net (loss) ($204) Adjusted EBITDAX (1) $202 Further Adjusted EBITDAX (1) $ Please see Non-GAAP Financial Measures for a description of Adjusted EBITDAX, Further Adjusted EBITDAX and related reconciliations to comparable GAAP financial measures and 2023 Senior notes, net of unamortized deferred finance costs of $12MM and $8MM, respectively. 3. Please see Adjusted EBITDA and DCF Reconciliation for reconciliations to comparable GAAP financial measures. 4. Land capex reflects cash spend. 52 ($ in millions) Cash CAPITALIZATION Three Months Ended December 31, 2016 Rice Energy $399 Rice Midstream Holdings $49 Rice Midstream Partners $22 Total cash and cash equivalents $470 Mezzanine equity $383 Long-term debt Rice Energy E&P credit facility 6.25% Senior notes due 2022 (2) $ % Senior notes due 2023 (2) $391 Total Rice Energy long-term debt $1,279 Rice Midstream Holdings credit facility $53 Rice Midstream Partners credit facility $190 Total consolidated long-term debt $1,522 Net debt $1,052 Leverage Rice Energy E&P 1.8x Rice Midstream Holdings (3) 0.1x Rice Midstream Partners (3) 1.1x Consolidated (1) 1.5x Capex Incurred (Excluding Acquisitions) D&C $163 Land (4) $38 RMH $33 RMP $22

53 Water Business Complementary to Core Gathering & Compression Business Source freshwater from rivers and other local sources in Pennsylvania & Ohio 2. Pump freshwater through permanent and temporary pipelines from sources to pads 3. Provide freshwater services to pads for completion activity (fee charged based on volume delivered) 4. Recycle produced water onsite and/or coordinate disposal via trucks (fee charged based on % of cost) Provides a faster, more efficient and reliable method of water transportation versus trucking Reduced emissions, noise, road repairs and safety incidents Highly accretive to RMP Enables RICE E&P to complete a greater number of stages per day versus trucking

54 Integrated Water Services Business Providing fresh water to support Marcellus and Utica completion operations Access to >36 MMgal/d of fresh water in PA and OH Water services business is complementary to gas gathering and compression services and has strong cash operating margins of ~75% WATER SERVICES AGREEMENTS OVERVIEW Assumptions Pennsylvania Ohio Fresh Water Usage (MMGal/well) (1) Weighted Average Fee (1) $0.056 $0.059 Operating Expense $0.022 $0.016 Cash Flow per Well $442,000 $817,000 Provides a faster, more efficient and reliable method of water transportation versus trucking Reduced emissions, noise, road repairs and safety incidents Volumetric fee structure is tiered to provide revenue and cash flow stability RMP also collects, recycles or disposes of flowback and produced water and charges 2% of cost Water service fee charged based on volume delivered to pad MMgal Q16 2Q16 3Q16 4Q16 PA OH 3rd Party 1. Affiliate and third party weighted average based on 15% total third party water volumes. 54